The production of hydrocarbons from low mobility reservoirs presents significant challenges. Low mobility reservoirs are characterized by high viscosity hydrocarbons, low permeability formations, and/or low driving forces. Any of these factors can considerably complicate hydrocarbon recovery. Extraction of high viscosity hydrocarbons is typically difficult due to the relative immobility of the high viscosity hydrocarbons. For example, some heavy crude oils, such as bitumen, are highly viscous and therefore immobile at the initial viscosity of the oil at reservoir temperature and pressure. Many countries in the world have large deposits of bitumen oil sands, including the United States, Russia, and various countries in the Middle East. The world's largest deposits, however, occur in Canada and Venezuela. Oil sands are a type of unconventional petroleum deposit. The sands contain naturally occurring mixtures of sand, clay, water, and a dense and extremely viscous form of petroleum technically referred to as “bitumen,” but may also be referred to as heavy oil. Indeed, such heavy oils may be quite thick and have a consistency similar to that of peanut butter or heavy tars, making their extraction from reservoirs especially challenging. Due to its high viscosity, these heavy oils are hard to mobilize, and they generally must be made to flow to produce and transport them. Indeed, such heavy oils are typically so heavy and viscous that they will not flow unless heated or diluted with lighter hydrocarbons. At room temperature, it is much like cold molasses.
As used herein, the term, “heavy oil” includes any heavy hydrocarbons having greater than 10 carbon atoms per molecule. Further, the term “heavy oil” includes heavy hydrocarbons having a viscosity greater than about 100 centipoise at reservoir conditions.
Conventional approaches to recovering heavy oils often focus on methods for lowering the viscosity of the heavy oil or heavy oil mixture so that the heavy oil may be mobilized and produced from the reservoir. One example of lowering the heavy oil viscosity includes heating the heavy oil. Such commonly used thermal recovery methods include a number of technologies, such as steam flooding, cyclic steam stimulation, and steam assisted gravity drainage (SAGD), which require the injection of hot fluids into the reservoir. A 100° F. increase in the temperature of the heavy oil in a formation can lower its viscosity by two orders of magnitude. Accordingly, heating formation heavy oils can dramatically improve the efficiency of heavy oil recovery.
U.S. Pat. No. 4,344,485 issued to Butler describes early embodiments of the steam assisted gravity drainage (SAGD) thermal recovery technique. Essentially, the SAGD method typically involves a pair of wellbores, a steam injection well and a production well. Steam is injected into the steam injection wellbore to introduce heat into the heavy oil reservoir which reduces the viscosity of the hydrocarbons therein, allowing the hydrocarbons to be produced through the production well. Although many variations exist, FIG. 10 illustrates one example of a SAGD heavy oil recovery system. In FIG. 10, a cross-sectional view of a heavy oil reservoir is shown depicting two SAGD well pairs in hydrocarbon reservoir 7. The first SAGD well pair comprises a first steam injection well 11A and a first production well 12A. The second SAGD well pair comprises a second steam injection well 11B and a second production well 12B. Operation of first steam injection well 11A in conjunction with first production well 12A creates first steam chamber 25A over time. Likewise, second steam chamber 25B is created over time by operation of second steam injection well 11B in conjunction with second production well 12B. As can be seen in FIG. 10, first steam chamber 25A and second steam chamber 25B are not yet fluidly coupled with one another. That is, first steam chamber 25A and second steam chamber 25B have not yet grown to a large enough extent to couple with one another. Over time, these two steam chambers 11A and 11B may grow to such an extent that they couple with one another to form combined steam chamber 26. In this way, more and more of the hydrocarbons in subterranean formation 7 are recovered and produced.
Infill production well 20 may be interposed between first steam chamber 25A and second steam chamber 25B to assist in recovering heavy oil between first steam chamber 25A and second steam chamber 25B. Eventually, given enough time, steam chamber 26 will grow to include within its boundaries infill production well 20. Once this occurs, infill production well 20 will then be able to recover the hydrocarbons between the two steam chambers 11A and 11B.
Generally however, the expansion of combined steam chamber 26 is partially a gravity-driven process due to the condensing of the steam which drains under the influence of gravity towards the first and second production wells 12A and 12B. Thus, as steam chamber expands, the angle θ shown in FIG. 10 becomes smaller. Consequently, because this expansion is in part gravity-driven, steam chamber 26 expands slower and slower the more the angle θ decreases. Accordingly, expansion of steam chamber 26 is known to be quite slow and take excessively long periods of time the closer steam chamber 26 approaches infill production well 20. Thus, a continuing disadvantage of this thermal recovery configuration is the long period of time required to establish steam chamber connectivity among SAGD well pairs and with their corresponding infill production wells, if any are present. Additionally, by the time communication is eventually established to infill production well 20, the remaining oil left to be produced is often too negligible to justify the installation of a costly infill production well.
Accordingly, enhanced methods for accelerating SAGD heavy oil thermal recovery methods are needed that address one or more disadvantages of the prior art, especially as relating to accelerating communication among SAGD well pairs and infill production wells if present.